The petroleum industry has recognized for decades that only a portion of original oil in place (OOIP) in oil-bearing reservoirs is produced by natural mechanisms. It is also well-known that conventional methods of supplementing natural recovery are relatively inefficient. Typically, a reservoir may retain half of its original oil in place even after the application of currently available methods of secondary recovery. Accordingly, there is a continuing need in improving recovery methods, which will substantially increase the ultimate petroleum recovery of subterranean reservoirs.
Waterflooding
Waterflooding is a method of secondary recovery in which water is injected into a reservoir formation to displace mobile oil within the reservoir formation. The water from injection wells physically sweeps the displaced oil to adjacent production wells, so that the oil can be collected from the production wells. Generally, the water used in a waterflooding process is taken from nearby water sources, which is usually either seawater or produced water.
It is known that a reduction in salinity values of the injected water can increase oil production for sandstone reservoirs. However, the low salinity floods have only been shown to work if the reservoir contains clays and with water having salinity values that are less than 5,000 ppm.
Carbonate reservoirs do not contain such clays. As such, the low salinity water flooding teachings known heretofore specifically teach away from the successful use of low salinity water for carbonate reservoirs. See A. Lager et al., “Low Salinity Oil Recovery—An Experimental Investigation,” paper presented at the Society of Core Analysts, September 2006 (“Finally it explains why LoSal™ does not seem to work on carbonate reservoirs.”). See also A. R. Doust et al., “Smart Water as Wettability Modifier in Carbonate and Sandstone,” paper presented at 15th European Symposium on Improved Oil Recovery, April 2009 (“The wettability modification in carbonates can take place at high salinities, i.e. SW salinity. If SW is diluted by distilled water to a low saline fluid, ˜2000 ppm, the oil recovery will decrease due to a decrease in the active ions.”).
Surfactant Flooding
It is known to add aqueous surfactants to injection water in order to lower the oil-water interfacial tension and/or alter the wettability characteristics of reservoir rocks. However, the previously known methods involved the injection of an aqueous surfactant solution in high surfactant concentration known as micellar or microemulsion flooding. The objective was to displace residual oil and water miscible by a mutually soluble solvent using an injected slug of micellar solution (containing a mixture of a surfactant, a co-surfactant, brine and oil), so that an oil bank was formed in the subterranean formation before its production started. This art is commonly used in tertiary recovery mode with a high surfactant concentration of 1 wt % to 10 wt % (10,000 ppm to 100,000 ppm).
The high costs associated with classical surfactant flooding techniques described above have inhibited the implementation of this technique, particularly in harsh environments. Non-limiting examples of harsh environments include reservoirs with high reservoir temperatures, high brine salinities, and fractured carbonate. As a consequence, research into surfactant flooding has been focused on using dilute surfactant solutions in an attempt to reduce costs.
The use of high salinity water, particularly at elevated temperatures, presents a major challenge for dilute surfactant flooding. For example, high salinity causes low efficiency of surfactants in several ways, including high interfacial tension between the dilute surfactant solution and crude oil, high adsorption onto the reservoir rock surface, and precipitation of white, cloudy, solid materials.
Therefore, it would be desirable to have an improved process for waterflooding carbonate reservoirs that was simple and efficient. Preferably, it would be desirable to have a process that did not require the use of complicated chemicals or gases such as carbon dioxide, polymers, or the like. Preferably, it would be desirable to have a process that did not use a substantial amount of surfactant, thereby allowing the process to be more economical. Additionally, it would be beneficial if the process for an improved waterflooding could be implemented with existing infrastructure.